Operations Seminar Managing Dispatch Balancing Costs 26 th May 2011
Agenda • Introduction • Overview of Dispatch Balancing Costs (30 mins) • Ongoing Management of Dispatch Balancing Costs (15 mins) • Forecasting Dispatch Balancing Costs (15 mins) • Q&A
1: Introduction
Introduction • Managing Dispatch Balancing Costs (DBC) is a TSO Role • Operations: Cross TSO Function – EirGrid: Operational Services & Performance (OSP) – SONI: Near Time Operations – Significant interaction with other groups within Operations
Operations Organisation Chart Director PA Fintan Slye Aoife Fogarty Power Grid Ops Grid Ops Power Power Operational Sustainable Grid East West TSO – Real – Near System System Quality & Services & Power Revenue Readiness Joint Control Time Time Operational Power Performance Systems & Projects (PSC) Planning System (OSP) (SPS) Metering (PSOP) Protection (GR&M) (PSP) Michael Alex Brendan Marie Sonya Jon Paul Rodney Michael O‟Sullivan Kelly Baird Woods Hayden Ray Doyle Twohig Killian Doyle Preston
2: Overview of Dispatch Balancing Costs
Dispatch Balancing Costs Uninstructed Constraint Costs Testing Charges Imbalances TSO Dispatch Balancing Costs (DBC) Tariff Year 2010/11: € 110.5m Funded by SEM Imperfections Charge Funded by Funded by Energy Imbalances Make Whole Payments
SEM Structure Dispatch TSO Generator Generator Generator Unit Unit Unit Wholesale Pool Market Supplier Supplier Unit Unit Generators offer in energy Suppliers buy @ SMP
Merit Order 400 350 300 OCGTs Flexible & Mid Incremental Price ( € /MWh) 250 (gas) merit Units e.g. Base Load Coal, Gas Units e.g. 200 CCGTs Zero price generation 150 e.g. Wind, Hydro 100 Expensive, low merit units e.g. Oil 50 & distillate 0 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 -50 System Demand (MW)
SEM: Market Schedule • Market Scheduling and Pricing (MSP) Software – Transmission and Security constraints not taken into account – Uses Generator commercial and technical data – Uses Generator Availabilities • Objective: Minimise Production Costs – 30 hour optimisation time horizon • Output – Price (SMP) for each half hour – Market Schedule Quantity (MSQ) for each Generator for each half hour
Generator Payments & Charges • Energy payments • Constraint payments • Uninstructed Imbalance payments DBC • Testing Tariffs • Make-Whole payments
Energy Payments • Energy Payments to all Generator Units based on: – Market Schedule Quantity (MSQ) – Market Price (SMP)
Example 400 350 300 250 200 150 100 50 0 Sun Mon Tue AA MSQ DQ AO
Example 400 350 300 250 200 150 100 50 0 Sun Mon Tue AA MSQ DQ AO
Energy Payment Price Market Schedule Quantity SMP € 55 P4 € 45 P3 Energy Payment € 30 P2 € 20 P1 Q2 Q4 Q1 Q3 Quantity 100 MW 250 MW 50 MW 180 MW
Energy Payment Price Market “Profit” Schedule Quantity SMP € 55 P4 “ Inframarginal Rent” € 45 P3 € 30 P2 Production Cost € 20 P1 Q2 Q4 Q1 Q3 Quantity 100 MW 250 MW 50 MW 180 MW
Constraint Payments • Apply if Market Schedule Quantity ≠ Dispatch Quantity • T&SC calculation: ( DQLFuh DOPuh DNLCuh DQCCLFuh ) CONPuh TPD DSUCuh MSUCuh ( MSQLFuh MOPuh MNLCuh MSQCCLFuh ) Constraint Payment = Production Cost (Dispatch) – Production Cost (Market) • Principle: Generators kept financially whole
Constraint Payments • Constraint payments can be positive/negative – If DQ > MSQ, Generator receives a payment – If DQ < MSQ, Generator makes a payment back • Production Cost includes: – incremental costs – start-up costs – idling costs • TSOs determine dispatch
Example 400 350 300 250 200 150 100 50 0 Sun Mon Tue AA MSQ DQ AO
Example 400 350 300 250 200 150 100 50 0 Sun Mon Tue AA MSQ DQ AO
Constraint Payments Price Market Dispatch Schedule Quantity Quantity (130 MW) SMP € 55 P4 “ Inframarginal € 45 P3 Rent” € 30 P2 Avoided Costs € 20 P1 Q2 Q4 Q1 Q3 Quantity 100 MW 250 MW 50 MW 180 MW
Constraint Payments Price Market Dispatch Schedule Quantity Quantity SMP € 55 P4 “ Inframarginal € 45 P3 Additional Rent” Incremental Costs € 30 P2 Incurred € 20 P1 Q2 Q4 Q1 Q3 Quantity 100 MW 250 MW 50 MW 180 MW
Constraint Payments Price Total Constraint Payment = Incremental cost + start cost + idling cost € 125 P4 Dispatch Quantity “Profit” € 95 P3 € 80 P2 Incremental € 70 P1 Costs Incurred Q2 Q4 Q1 Q3 Quantity 40 MW 90 MW 20 MW 70 MW
Uninstructed Imbalance Payments • Uninstructed Imbalance Payments apply if Actual Output differs from Dispatch Quantity • Tolerance bands set annually – Take actual system frequency into account, thus allowing for regulation – Within tolerance band: • Uninstructed Imbalance Payments based on Imbalance amount – Outside tolerance band: • Uninstructed Imbalance Payments based on Imbalance amount with an additional factor included
Example 400 350 300 250 200 150 100 50 0 Sun Mon Tue AA MSQ DQ AO
Example 400 350 300 250 200 Under-generation 150 100 Over-generation 50 0 Sun Mon Tue AA MSQ DQ AO
Uninstructed Imbalance Payments Price Actual Actual Output Output DQ MSQ SMP € 55 P4 € 45 P3 € 30 P2 € 20 P1 Q2 Q4 Q1 Q3 Quantity 100 MW 250 MW 50 MW 180 MW
Testing Charges • For a Generator Unit that is under test in SEM • Testing Charges apply per MWh of output • Testing Tariff is based on registered capacity Testing Charge = Max (Metered Gen, 0) * Testing Tariff
Make Whole Payments • Ensures that all Generator Unit Operating Costs are met • If costs are NOT met through other market payments, make whole payments apply: Make Whole Payment = Max (Operating Cost - Payments received, 0) • Calculated on a Billing Period basis (1 week) • Make Whole Payments only necessary in exceptional circumstances - SMP should generally cover all operating costs.
Dispatch Balancing Costs Uninstructed Constraint Costs Testing Charges Imbalances TSO Dispatch Balancing Costs (DBC) Funded by SEM Imperfections Charge Funded by Funded by Energy Imbalances Make Whole Payments
What Causes Constraints? • Generators receive constraint payments to keep them financially neutral for the difference between the market schedule and actual dispatch. • The main drivers of constraints costs are: – Reserve – Transmission – Perfect foresight – Market modelling assumptions – System security constraints – SO Interconnector Trades
1: Reserve Constraints 50 Hz 51 49 48 52 Generation Demand • Reserve: Additional power capacity available from generators or through reduction in load
1: Reserve Constraints • Reserve required to ensure continuity of supply in the event of a generator/interconnector trip • Part loading generators frees up spare capacity for quick response • In-merit generators are constrained down Additional generators constrained on • The market schedule does not account for reserve requirements
Merit order illustration Demand € 200 € 180 € 160 Generation Generation dispatched down dispatched up € 140 € 120 € 100 € 80 € 60 € 40 € 20 € 0 0 1000 2000 3000 4000 5000 6000 7000 System Demand (MW)
2: Transmission Constraints
2: Transmission Constraints • Required for safe and secure operation of the transmission network – power flows on transmission circuits and system voltages must remain within limits • Generators constrained on/up – E.g. to support voltages in weaker parts of the network • Generators constrained off/down – E.g. when a line outage means that there is insufficient capacity to export all available power • Market schedule does not account for these physical limitations on the transmission system
Merit order illustration Demand € 200 € 180 € 160 Generation Generation dispatched down constrained on € 140 € 120 € 100 € 80 € 60 € 40 € 20 € 0 0 1000 2000 3000 4000 5000 6000 7000 System Demand (MW)
3: Market Modelling Assumptions • Due to limitations of market software – approximations and assumptions made in the MSP software – market schedule will not always be physically feasible • TSOs and generators: bound by the technical realities of operation • Actual dispatch will differ from the market schedule regardless of any transmission and security constraints
4: Perfect Foresight • The market schedule is calculated ex-post by MSP Software
TSOs Indicative Send Data Dispatch Forecasts Actual • Meter Data • Load • Dispatch Instructions Schedule • Wind Real Time • Availabilities 16:00 D-1 Gate Closure Trading Day D D-1 10:00 Ex-Ante Ex-Post Ex-Post Market Market Market Schedule Schedule Schedule 11:00 D-1 D+1:Indicative D+4:Initial SEMO
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